The present invention provides a process for improving hydrogen recovery as well as the overall economics of a reactor complex that includes multiple reactors utilizing hydrogen.
Hydrocracking is a hydroprocessing process in which hydrocarbons crack in the presence of hydrogen and a hydrocracking catalyst to lower molecular weight hydrocarbons. Depending on the desired output, a hydrocracking unit may contain one or more beds of the same or different catalyst. Hydrocracking can be performed with one or two hydrocracking reactor stages. In single stage hydrocracking, only a single hydrocracking reactor stage is used. Unconverted oil may be recycled from the product fractionation column back to the hydrocracking reactor stage. In two-stage hydrocracking, unconverted oil is fed from the product fractionation column to the second hydrocracking reactor stage. Slurry hydrocracking is a slurried catalytic process used to crack residue feeds to gas oils and fuels.
Due to environmental concerns and newly enacted rules and regulations, saleable fuels must meet lower and lower limits on contaminants, such as sulfur and nitrogen. New regulations require essentially complete removal of sulfur from diesel. For example, the ultra-low sulfur diesel (ULSD) requirement is typically less than about 10 wppm sulfur.
Hydrotreating is a hydroprocessing process used to remove heteroatoms such as sulfur and nitrogen from hydrocarbon streams to meet fuel specifications and to saturate olefinic compounds. Hydrotreating can be performed at high or low pressures, but is typically operated at lower pressure than hydrocracking.
A hydroprocessing recovery section typically includes a series of separators in a separation section to separate gases from the liquid materials and cool and depressurize liquid streams to prepare them for fractionation into products. Hydrogen gas is recovered for recycle to the hydroprocessing unit. A stripper for stripping hydroprocessed effluent with a stripping medium such as steam is used to remove unwanted hydrogen sulfide from liquid streams before product fractionation.
In addition, in many plants there are additional units that employ hydrogen to further convert hydrocarbons as needed.
Efficient use of hydrogen is critical to the economics of a hydroprocessing unit. In current projects there is a continued need for higher efficiencies. For example, in a complex that consists of a hydrocracking unit, catalytic reforming unit, and aromatics unit that is not including a pressure swing adsorption (PSA) unit, it is desirable to reduce both capital and operating expenses by reducing equipment count and by integrating process operations to improve efficiency.
Sometimes, the complex containing several individual units is offered with a PSA unit to derive pure hydrogen (99.9 mol %) that is used as make-up gas to the hydrocracking unit. This PSA unit is typically fed with catalytic reforming net gas at 300 to 400 psig and produces a hydrogen product at a recovery rate of 85 to 90%. Due to the high value of hydrogen, a method is needed to increase hydrogen recovery from the PSA unit. The overall economics of the complex is sensitive to hydrogen balance/utilization, and it has been found that increasing PSA hydrogen recovery can have a significant benefit.
This invention is intended to improve hydrogen balance across the complex and importantly increase the value of the overall complex by including a PSA unit in the make-up gas compression system of the hydrocracker. Operating this PSA unit at a significantly higher pressure (500 to 1000 psig) increases hydrogen recovery by—3 to 6 percentage points, thereby improving overall economics of the complex. In addition to improved hydrogen recovery, the higher pressure also provides an opportunity to eliminate booster compressors associated with other units in the complex and reduce equipment count. This invention can also be applied to other types of hydroprocessing units.
In current practice (prior art), a conventional (low-pressure) stand-alone PSA unit is typically used to recover high-purity hydrogen from refinery off-gas streams, such as catalytic reforming net gas. This purified hydrogen supplies both low-pressure and high-pressure consumers in the complex. Hydroprocessing units are typically the largest hydrogen consumers, and they operate at a higher pressure than current practice, conventional (low pressure) PSA units. For example, hydrocrackers may operate from about 1500 to about 2500 psig and hydrotreaters may operate from about 500 to about 1800 psig. The high pressure hydrogen consumers typically require multiple stages of make-up gas compression to raise the lower pressure PSA hydrogen to reaction system pressure. Thus, it would be desirable if possible to integrate a high-pressure PSA into a hydroprocessing unit in order to utilize the higher pressure to achieve increased hydrogen recovery.
An important and unexpected feature of this invention is the preferred pressure level of the PSA unit. It has been found that including a PSA unit within a hydroprocessing unit make-up gas compression system, for example, between typical 1st and 2nd compression stages (about 500 to 1000 psig) provides an economic and increased level of hydrogen recovery. Increasing PSA pressure greater than about 1000 psig that is, between typical 2nd and 3rd stage compression stages, provides little additional benefit in terms of hydrogen recovery and greatly increases cost. This invention provides a competitive and business advantage by integrating PSA units to provide a synergistic benefit that is not possible with a conventional, stand-alone PSA unit.
In addition, it has been found that reducing PSA feed gas temperature below that which can be achieved with air or water coolers (currently practiced) by using a chiller (refrigeration) provides a benefit to PSA performance. PSA simulation results show that hydrogen recovery increases and bed volume decreases with decreasing feed gas temperature. A preferred feed gas temperature for this application is in the range of 10 to 20° C. This added feature of PSA integration in the make-up gas compression system of hydroprocessing units provides a significant advantage. An important aspect of this invention is the finding that the added capital and operating cost increases due to the use of a chiller is offset by the decrease in costs attributed to downstream compression and the ability to have a smaller size PSA unit. It has been found that the beds may be up to 25% smaller at the lower temperature. Furthermore, the downstream Stage 2 and PSA tail-gas compression power is reduced due to lower compressor inlet temperature. The net result of adding the chiller is a small decrease in costs, and about 1.0 percentage point increase in hydrogen recovery.